Oil/Gas/Drilling Oil and Gas
I read through your short brief on what to ask and what not to. I'd like understand from you the different ways by which drilling is done for oil and gas. which method is faster / costlier. If this question sounds too broad to you. then never mind. could you just list down key pointers which i need to keep in mind. I am actually doing a research on the upstream phase of Oil and Gas. I'd appreciate if you could share your insights on the topic.
This sounds like classwork to me but I will try anyway.
I will try and with these assumptions: land well and directionally drilled and drilling only. For both the “high tech” and “low tech” well the cost of bits, casing and mud will be similar so the criteria for the project manager will be the selection of a particular drilling unit and the drilling services. No completion because some of the completion types lock one into only one way of doing it.
As a general rule faster = costlier per well = less costly per project. If a company running several rigs and on a long term project can shave 3 or 4 days off of each well they can, by years end, save enough time to add one or more wells per year. This brings their project on line sooner and may also help them get to a lease before it expires. This is the goal of operators with large holdings in the shale fields.
A company that wants to add a well or two to an existing field may opt for a little slower/less costly in order to finance it out of daily cash flow in that field. The differences is in the methods you are asking about.
First the rig. Oil or gas wells can be drilled with the same rigs, the difference is in handling oil or gas, not the drilling techniques. Almost all rigs now have top drive instead of the older Kelly drive but some have greater automation than others.
The well with the higher daily cost and theoretical higher efficiency will have:
1. Drill pipe and casing handling systems with pipe racks that move and connect the tubulars automatically to the same torque.
2.Computerized mud pumps that can be programed to maintain a set flow rate or pressure that adjusts for downhole conditions.
3.A top drive that can be set to operate in different ways to expedite directional drilling. Rocking, rotate/slide intervals, steady ROP etc.
4.Computerized drilling fluids systems that can be setup to maintain weight and chemical mixes.
5.It will use down hole steerable directional drilling assemblies that can change the angle of the bit motors without having to pull them out and replace them.
6. It will use Log While Drilling and Real Time Down Hole Pressure Bottom Hole Assemblies in order to collect formation data earlier and reduce the completion program planning time.
7. The casing installation and cementing operations will use higher cost rotate and circulate while running tools and duplicated, redundant cementing units.
The well with the lower daily costs and theoretical longer drilling time may use a rig that is an earlier generation of rig equipment.
1.Drill pipe and casing handling that uses rig and service crews to move the tubeulars into place and using less computerized make up machines.
2. Mud pumps that are monitored and controlled only by the rig crews.
3. It may use an older top drive that will operate in different ways to accommodate directional drilling but the drillers must do it manually.
4. Drilling fluid systems that use the older “open and pour X number of sacks per hour” system. This works fine but takes closer supervision from the Mud Engineer and/or Driller.
5. It may use standard directional drilling Bottom Hole Assemblies that require pulling and replacing if surveys show that directional changes are needed.
6. Gamma Ray only or no Log While Drilling tools may be used.
7. Casing installation and cementing may not have redundancy. In case of problems the operator may choose to pull the casing out of the hole or to circulate to pump the cement away and wait on replacement equipment.
These are a few of the alternate choices to do the same things. An operator may be willing to accept longer time or even some non-productive time (Down Time) on a one or two well project that is not using a Line of Credit to finance it. An operator in a more hectic, boom type area cannot. One of the problems facing operators in the Eagle Ford Shale area is the expiration of the first leases so they must do all they can to drill as fast as possible.